2023 global LNG demand growth registered a +2% y/y increase, with Europe and Asia having represented the major desnaon markets. An overall +2% yearly recovery is foreseen also in 2024, resulng from incoming new regasificaon capacity worldwide. European LNG intake is expected to remain sustained in the short-term to ensure reliable and affordable energy supplies, reaching +6% y/y in 2024. 2023 Chinese LNG demand growth rate remained close to +10% y/y, following a faster than expected recovery of the Chinese industrial and transport sectors. LNG deliveries to China should grow also in 2024, but at a slower pace (+5% y/y) with ramping up Russian deliveries via the Power of Siberia pipeline entering the market. Compeon should be intense also in 2025, when the world regasificaon plants will work at their maximum capacity, leading the global LNG demand growth to accelerate above +5% y/y.

Only after 2025, when the new super-cycle of LNG supply from US and Qatar will begin to flood the market, the global LNG demand-supply margin would widen beyond 15%, providing the basis for a full normalization of prices.

In the long-term, pressure on the LNG market is expected to ease, with new capacity growing and green energy commitments becoming effective.

The TTF 2024 average price settled just above 30 €/MWh, in line with our Reference scenario’s expectations, due to the persistently easing of market fundamentals resulted by the combination of subdued demand and record-high gas storage across Europe. As the European regassification capacity deployment will increasingly enable further LNG arrivals, prices may move higher amid restoring competition with Asia on securing supplies, leading the 2025 TTF yearly average close to 33 €/MWh consequently. A gradual normalization is expected from 2025 on wards following the significant stationing of new liquefaction capacity, with the TTF gas prices moving just above 35 €/MWh.

Under the assumption of a progressive normalizing of the world LNG market combining with an acceleration of the energy transition, the European gas prices would move gradually lower towards 30 €/MWh in 2030.

European decarbonization process would keep reducing gas demand, pressuring the price action back towards the 25 €/MWh long-term equilibrium. Only in the High scenario, persisting geopolitical and commercial tensions would leave commodities shortages unresolved, leaving prices just below the 50 €/MWh threshold in the long-term. Effective green policies supported by economic growth may lead prices significantly lower in the Low scenario, with the TTF averaging near 10 €/MWh in the long-term.

The PSV-TTF spread is still seen as remaining positive in short term, just below 2 €/MWh on average, with some variability across the year depending on the season, as the reliance on flows from Northern Europe via Passo Gries is still pivotal to the Italian gas demand coverage.

Flows from the TAP and Algeria, and LNG arrivals are seen as balancing imports in the medium-term, leading to a progressive spread closure to below 1 €/MWh by 2030.

The PSV-TTF spread is foreseen to reabsorb towards zero in the long-term, since a gradual flows re-balancing is expected to combine with the underlying decarbonization-induced demand reduction

The 2023 PSV average price settled just below 45 €/MWh in 2023. In 2024, with the fully operational Piombino Floating Storage Regasification Unit (FSRU) and the new Ravenna FSRU (expected to become operational by the end of 2024) supporting the gas demand recovery, the PSV yearly average should move higher, staying above 50 €/MWh. In the High scenario, further escalation of geopolitical tensions, increased competition on LNG supplies and/or limited Norwegian flows combining with lower than average winter temperatures would emphasize the market upward potential, with the yearly PSV averaging 80 €/MWh in 2024. Should the global economic recovery stall and no competition arise on gas supplies as both European and Asian demand remain muted instead, the gas prices decline may continue, with the PSV averaging below 30 €/MWh, as represented in the Low scenario.

The PSV is expected to follow the European gas prices mid-term normalization towards 30 €/MWh by year 2030, as a gradual re-balancing of the global gas demand-supply dynamics should follow the expected acceleration of energy transition.

The PSV Reference price is expected to stabilize, aligning to TTF prices at around 25 €/MWh in the long- term.

The 2023 logistic cost for Italian gas-fired units averaged 4 €/MWh amid the increase of the CRVOS (which pays storage injections incentives), CRVBL (which covers the charges associated with the gas system balancing activity) and the CVU (which covers variable charges and it’s linked to the gas price trend) components. With the Consultation Document 588/2023/R/gas ARERA is evaluating the introduction of a Neutrality Charge of 2.2 €MWh from April 2024 (and for at least 3 years) to recover almost 4 Bln€ derived from the summer 2022 last resort buying activity put in place to refill the Italian storage. The overall gas transport cost should therefore remain above 4 €/MWh at least unl 2026. The CRVOS component should reduce close to pre-crisis levels starting from October-2024 instead.

A gradual normalization of the average variable logistic costs is expected from 2027 on wards, following the normalization of gas prices, nearing 1.6 €/MWh on average by 2030.

In our Reference scenario, the 2024 CO2 price average should near 90 €/ton, with the gradual implementation of the ETS system reform supporting CO2 prices. The inclusion of the maritime transport sector in the ETS scheme (as set by the EU Directive 2023/959) will be gradual too, possibly not having a significative impact on the allowances demand in the short-term. Moreover, there are still concerns about the effective demand recovery, which should be limited over the next couple of years amid as a result of an expected slow economic growth.

A significant widening of the supply-demand gap should become evident from 2027 on wards, when the inclusion of the maritime sector in the ETS system will be in full swing, leading to a ght market, with CO2 prices accelerating towards 110 €/ton on average by 2030.

The long-term targets would still depend on the effective efficiency of the ETS System, with the CO2 price expected to target over 120 €/ton in the Reference scenario by 2040, and a possible acceleration just below 150 €/ton in the Low scenario, under the assumption of stricter decarbonization efforts in Europe to accelerate the prices increase.

Reduction in electricity demand and recovery in hydro generation at national and European level stabilize the system needs, leading to the interruption of the coal maximization program. Gas generation remains the main generation source, continuous installation of RES driven by solar technology increase renewable quota in the MIX.

The Capacity Market (CM) brings 7.3 GW of new thermoelectrict capacity and more than 1.5 GW of new storage capacity online between 2024 and 2025. In 2025, coal-fired units in the peninsula are phased-out, while Sardinian units remain operative for security reasons until the completion of the Tyrrhenian Link, in 2030. Renewables production growth hit almost 50% of demand in 2030. The progressive normalization of commodities prices drives the reduction of imported flows.

Further reductions of net import flows from the northern borders could be determined by the partial decommissioning of the ageing French nuclear fleet, the phase-out of German coal-fired capacity, and the realization of the Elmed cable (Tunisia-Sicily). Renewables become the main source in the mix, backed up by gas-fired production. Convenient market conditions would favor the development of energy intensive storage.

With commodities prices rebounding faster and an improved economic outlook, there is a renewed commitment to decarbonizing the economy. Facilitating the prompt resolution of authorization deadlocks for new renewable projects and encouraging investments in energy efficiency. Although coal units continue to operate, their share decreased due to more favorable conditions for gas. Gas-fired production reach 34% of the national electricity demand.

In 2029 coal-fired units in the are entirely phased-out. Falling renewables costs and a greater effort to reach decarbonizations goals support renewables development: in 2030 the ratio between renewable energy and total electricity consumption reach 59%. The combination of reduced fuel prices – affecting competitive dynamics between different production sources all over Europe – and the need to respect national grid security conditions drive the progressive reduction of imported flows.

In the very long-term, gas-fired generation and energy intensive storage systems back up non- programmable renewable production and guarantee system security and adequacy. Despite storage and network reinforcements the integration of renewables in the energy mix will only be partial reached as congestion and overgeneration problems are going to manifest, generating signals for electrolisis capacity.

Coal-fired units become essential to grant security, adequacy conditions and to reduce gas consumptions in a context of higher than historical price level. Coal-fired output reaches 10 TWh and gas-fired production reach around 31% of total electricity needs.

CM-led investments come online but the phase-out of coal-fired capacity is postponed, so as the realization of great network investments. Net imports remain stably above the 40 TWh threshold and gas-fired production maintains a 31% quota of total electricity needs, as hydro production normalize and renewable energy sources gradually increase their share in the mix

Increase in CO2 price reduce coal generation compeveness until 2035 when the entrance of the Tyrrhenian Link determine the phase-out of all coal units. Gas-fired production increases its share in the national energy mix to around 38%. Volatile DAM dynamics and RES development sustain the entrance of 10GW of energy intensive storage in the long-term.

Electric vehicles are assumed to increase up to 1.2 million in 2025, 4.5 million in 2030 and 11 million in 2040, bringing 2 TWh, 7.6 TWh and 18.7 TWh of additional consumption, respectively. In the Low scenario, a greater diffusion of electric vehicles leads 10.5 million in 2030 and 14 million in 2040. In the High scenario, e-mobility development suffers a 5-year delay compared to the Reference case.

The NIECP envisages 6 million electric vehicles in Italy in 2030 - 4 million are pure EVs (BEV: Battery Electric Vehicles) – accounting for about 8 TWh of additional electricity demand. In our Reference view we estimate additional 7.5 TWh to come from BEV and PHEV (Plug-in Hybrid Electric Vehicle). This means that our hypotheses consider a greater consumption per EV compared to NIECP figures. Main differences are most likely connected to the underlying assumptions about e-mobility applications in cities or long-term transport.

Notwithstanding the newest Green Deal proposals at EU level concerning transports, considering the uncertainty connected to the future expansion of a market which is still in a first stage of development, we assume a BAU trend in the long-term horizon, starting from the annual level of EVs addition reached in 2030.

H&C is expected to account for additional electricity requirements in a range between 2.5 TWh and 8 TWh in 2025, 4 TWh and 16 TWh in 2030, 7 TWh and 18 TWh in 2040, depending on the scenario considered.

Our assumptions lead to estimate 6.7 TWh of H&C consumption in 2030, corresponding to around 1.8 million installations for civil uses.

We assume a BAU trend in the long-term horizon, starting from the annual level of additional installations and consumption reached in 2030.

Law 91/2014 affirms that grid and general system tariff components should be applied to the electricity consumed and not only to the electricity withdrawn from the public grid. Following this approach, the exemptions accorded to RIU (Re Interne di Utenza) and SEU (Sistemi Efficienti di Utenza) and closed distribution systems, and the benefits currently in force for existing plants related to self-consumption will be at least partially removed for new subjects/projects that apply for similar mechanisms.

The excess of self-produced electricity that is not consumed by the industrial sites (self-consumption) and is thus sold on the market (differential between self-production and self-consumption) is expected to gradually decrease, consistently with the expected end-of-life of existing power plants that serve industrial sites.

In 2015, the approval of the European guidelines on capacity allocation and congestion management (CACM) introduced new parameters to be followed in the zonal configuration review process. In 2018, Terna began a process to review the zonal configurations in compliance with such rules.

The current zonal configuration derives from the base case proposed by Terna in compliance with the CACM. Differences compared to the previous configuration: (i) elimination of the limited production poles, (ii) inclusion of a new bidding zone corresponding to the Calabria region, (iii) displacement of the Umbria region from the Centre-North zone to the Centre-South market zone.

The zonal distribution of electricity demand is based on historical regional data published by Terna and subsequent econometric elaborations. In the Reference case, the zonal distribution of electricity needs is as follows: North (57%), Central-North (9%), Central-South (17%), South (7%), Calabria (2%), Sicily (6%), Sardinia (3%). Slight differences in such figures between the alternative cases are the result of the econometric elaborations performed.

Due to troubles in completing the perming process, some capacity procured through the 2022-2023 Capacity Market (CM) auctions will not be realized. According to the latest data published by Terna, the total amount of new gas-fired capacity supported by 2022-2023 CM premium should total around 5 GW.

The first results of the 2024 CM auction show that around 1.8 GW of new gas-fired capacity has been procured and will enter the market between late 2024 and mid-2025. Auction results show also that Sardinian coal-fired capacity will not be substituted by gas-fired units, as only storage capacity was awarded in the island. Anyway, while coal-fired plants on the peninsula will be phase-out after 2025, Sardinian units are expected to operate until the Tyrrhenian Link infrastructure is fully completed (2030).

The amount of capacity auctioned through the CM is expected to grant full system adequacy at least through to 2030. No other thermoelectric capacity investments are envisaged after the wave of investment brought by the last CM auctions. Existing CHP power plants continue to support industrial acvities under the assumption of a BAU evolution of the industrial needs they serve. Some ageing CCGT capacity exit the market.

Due to troubles in completing the perming process, some capacity procured through the 2022-2023 Capacity Market (CM) auctions will not be realized. According to the latest data published by Terna, the total amount of new gas-fired capacity supported by 2022-2023 CM premium should total around 5 GW.

The first results of the 2024 CM auction show that around 1.8 GW of new gas-fired capacity has been procured and will enter the market between late 2024 and early 2025. Sardinian coal-fired plants are phase-out in 2025 together with power plants located in the peninsula under the hypothesis of a quick realization of the Tyrrhenian Link infrastructure.

No other thermoelectric capacity investments are envisaged a􀅌er the wave of investment brought by the last CM auctions. Most of existing CHP power plants gradually exit the market, substituted by greener solutions. Some ageing CCGT capacity exit the market following strong competitive conditions.

Due to troubles in completing the perming process, some capacity procured through the 2022-2023 Capacity Market (CM) auctions will not be realized. According to the latest data published by Terna, the total amount of new gas-fired capacity supported by 2022-2023 CM premium should total around 5 GW.

The first results of the 2024 CM auction show that around 1.8 GW of new gas-fired capacity has been procured and will enter the market between late 2024 and early 2025.

No other thermoelectric capacity investments are envisaged after the wave of investment brought by the last CM auctions. Existing CHP and CCGT power plants are remain operative. Realization of the Tyrrhenian Link in 2035 determine the phase-out of all coal power plants.

Due to reversed coal-to-gas switching conditions, the existing CCGT fleet is supposed to average about 2200 EOH in the 2024-2025 period in the Reference case. In the alternative scenarios, the diverse results depend on the different switching conditions: in the Low scenario, the 2024-2025 average is 2200 EOH, while in the High scenario the figure drops to 2000 EOH. In the same period, min-max performances of new, high-efficiency CCGTs range between 4000 EOH and 6300 EOH (considering the three cases).

A􀅌er the phase-out of coal-fired units, the residual demand rebounds but existing CCGTs suffer the competition brought by sustained import levels and new high-efficiency competitors entering with the Capacity Market support. In the Low scenario, residual demand is furtherly reduced by the energy efficiency effect on consumption and the greater renewable penetration. In the High scenario, the progressive increase of residual demand is due to improving switching conditions.

Existing CCGTs (53%-efficiency) stabilize around 2400 EOH. In the Low scenario, the great renewable penetration influences competitive dynamics and existing units remain close to 1600 EOH. In the High scenario, the improvement of switching conditions is hampered by the high level of imports from abroad, with EOH of existing units over 2000 favored by catiol phase-out after 2035. High-efficiency units stabilize below the 4800 EOH only in the Low scenario.

Starting from the end of 2021 coal-to-gas switching conditions favored a recovery of coal-fired production. Measures implemented to reduce gas, such as coal power plants maximization program, are expected to guaranty high operativity of coal plants in the short term, with production levels reaching 17 TWh in the Reference case and 18 TWh in the High scenario. In the Low scenario the quicker reasorbaon of commodities prices limits the recovery of coal-fired production to a 12TWh.

Coal phase-out in the different scenarios depend on the functionality of the main grid infrastructure (Tyrrhenian link). In the Reference case only the units in Sardinia will connue to operate after 2025 until the Tyrrhenian Link is completed in 2030. In the Low scenario all units will be phased out by 2025. However, in the High scenario coal-powered units may continue to operate until 2035.

Coal units remain operative only in the High scenario unll phase-out in 2035, with the entrance of the Tyrrhenian Link, with favorable conditions for coal switching price most of the units are going to be in an economical phase-out, only the most efficents remains operative.

In the Reference case, the potenal for renewable development is considered based on recent trends, taking into account both bureaucrac and technical obstacles. This results in an esmated increase of 7.4 GW of solar and 2 GW of wind capacity. In Low scenario, there is a greater emphasis on achieving a decarbonized economy,with 10 GW of solar and 2 GW of wind power. High scenario, the growth of renewables is hindered by unfavourable economic condions, resulng in an increase of just 5.4 GW and 0.6 GW of new solar and wind capacity, respecvely, over the same two-year period.

Market parity condions will accelerate the progress towards achieving long-term targets. In the Reference case, there is an ambious plan for the development of renewables with an esmated 49 GW of solar and 16 GW of wind capacity by 2030, allowing to reach almost 50% of the energy demand. This scenario assumes a market-driven evoluon of the sector. Low scenario reach 63 GW of solar and 21 GW of wind capacity by 2030, development achieved through a faster decrease in technology costs.

The Reference scenario predicts a connued increase in renewables penetraon, with solar and wind capacity expected to reach 69 GW and 27.6 GW, respecvely, by 2040. However, an even faster transion towards achieving long-term decarbonizaon goals may be possible with the help of greater-than- ancipated investments in grid infrastructure and high-capacity energy storage soluons. These investments could enable an accelerated convergence towards meeng long-term decarbonizaon objecves.

In the next two years, solar and wind produco are assumed to reach past 35 TWh and 26 TWh by 2024. In the Low scenario, instead, the greater technological and praccal development of projects leads to reach past 41 TWh (solar) and 27 TWh (wind) in the same period.

Assuming a BAU evoluon of the market and the eliminaon of perming process constraints in the next future, an 90% quota of the 2030 RES/GDC rao target is expected to be achieved. Only a greener evoluon of the Italian system is expected to be able to lead to the full achievement of the target (55+ %). The achievement of Green Deal targets – possibly RES/GDC around 70%, yet to be defined – would surely require a greater effort instead.

The reducon of technology costs and consolidated market parity condions could allow solar producon to almost quadruple and wind generaon to more than triple with respect to 2022 values in 2040 in the Reference scenario. Boundary condions of alternave scenarios lead to different degrees of renewable development and producon level.

BAU market condions and moderate renewable penetraon lead to a minimum risk of overgeneraon in Reference and High scenario, while a more sustained increase in capacity installaon in the south macro- zone could lead to overgeneraon in some hours.

Greater penetraon of renewable energy sources expected a􀅌er 2026, there is a possibility of overgeneraon starng to increase, which could result in more than 3 TWh of excess electricity in the Low scenario by 2030. The curtailment effect may be emphasized in certain local grid condions. Moreover, during this decade, overgeneraon is likely to be exacerbated by the rapid development of renewable energy sources in the southern regions of the country and the lack of adequate grid reinforcement.

In order to effecvely manage the growing penetraon of renewable energy sources and the associated overgeneraon phenomena, the 2030s will require significant investments in grid reinforcements and high- capacity energy storage soluons. These measures will be crucial for balancing the grid and ensuring stable energy supply, especially in regions that are parcularly prone to overgeneraon. This excess energy producon could provide opportunies for the installaon of electrolysis capacity, which would not only help to take advantage of excess energy producon but also support ongoing investments in RES

In the long-term the development of renewable capacity, in parcular in the southern zones, increase the presence of systemac overgeneraon in the system, mainly in the islands. Grid investments and BESS are going to be insufficient to migate the problem, creang favourable condions for green hydrogen, installed electrolysis capacity could reach almost 0.5 GW in the Reference scenario, concetrated in Sardinia. In the long-term, electrolysis capacity can effecvely address overgeneraon by providing a means to store excess renewable energy. Addionally, by increasing demand during periods of high RES producon, it can help sustain prices and migate the cannibalizaon effect, parcularly during the advanced transion phase.

Despite some increase in technology costs, the solar energy sector connues to achieve market parity due to sll high in commodity prices, which are reflected in market prices. As baseload prices are expected to sele above 120€/MWh during the 2024-2025 period, solar power plants are projected to capture rates that are significantly higher than the esmated levelized cost of electricity (LCOE) across all scenarios. This indicates a posive outlook for the solar energy industry, which is likely to remain compeve and profitable in the near future.

Despite the potenal cannibalizaon effect on unlevered projects located in southern regions, market opportunies for merchant investments are expected to strengthen in the coming years.

The long-term outlook from 2030 onwards appears promising for the renewable energy sector, as the ongoing reducon in technology costs and the adopon of improved PPA best pracces are expected to support non-incenvized investments. However, the cannibalizaon effect could become a significant factor in certain regions, such as Sardinia and Sicily, where the grid infrastructure may not be capable of efficiently redirecng energy flows.

Wind market parity consolidates despite some increase in technology costs benefing from the bullish trend of commodies that influence market prices. With yearly captured prices aligned to baseload prices, wind power plants are expected to achieve promising results, above the esmated levelized cost of electricity (LCOE) in all the scenarios.

Market opportunies for merchant investments are expected to consolidate, as wind assets do not suffer from cannibalizaon effects. Site-specific maers may however influence project economics.

Long-term perspecves from 2030 onwards are promising, following the connuous reducon of the cost of technologies and improved PPA best pracces to support non-incenvized investments.

Within-day price spreads on the DAM could disclose opportunies for pumped hydro units, although the Ancillary Services Market (especially the real-me balancing phase) is expected to connue to be their main source of revenues.

Renewables development gradually increases the opportunies on the DAM. An accelerated development compared to the expected BAU trajectory could lead pumped hydro producon volumes to reach 3.5 TWh in the Low scenario.

With a penetraon of non-programmable renewable sources above 50% of total electricity needs, market opportunies furtherly increase: pumped hydro units help migate the solar cannibalizaon effect and help contain network congesons.

The first BESS (Baery Energy Storage System) projects are expected to come online in 2023 following the results of the Fast Reserve aucons held in December 2020. The pilot project proposed by Terna is based on the supply of a specific ultra-fast frequency regulaon service paid with a fixed yearly capacity remuneraon and is the first experience of development electrochemical storages in the italian market.

PI storages (1 hour of storage capacity) penetraon is sustained by growing needs on the BM as non- programmable renewable capacity progressively increases, in the first years. A􀅌er reaching the peak in the mid 20s, power intensive gradually contract, due to opportunies for converng their units in energy intensive storage to capture the increase volale dynamics on DAM. Increased overgeneraon and contracion in ASM volumes reduce determine a gradual end in PI investments

Power intensive BESS capacity gradually disappear in the Reference and High scenario, progressively replaced by energy intensive BESS as they reach the end of the operaonal life, and remain available only in the Low scenario where higher RES capacity generate operavity signals on the ancillary service market.

2024 Capacity Market aucon started the development of energy intensive storages in the Italian market, with more than 1.5 GW of new storage capacity – quite completely energy intensive (4 hours) – expected to hit the market by 2024 (possibly with some delays due to issue on the supply chain), with Sardinia and North to host about 0.8 GW and about 0.6 GW respecvely.

The Day-Ahead Market presents promising market opportunies for merchant energy-intensive storage applicaons with a storage capacity of 4 hours. This is due to the increasing price spread volality and the presence of overgeneraon resulng from the development of renewable energy sources. Addionally, the gradual decrease in technology costs further enhances the aracveness of energy-intensive investments.

Energy intensive applicaons reach an overall installed capacity of 22 GW in 2040. The larger installed capacity achieved in the Low scenario (near 31 GW in 2040) is consequence of greater opportunies both on the DAM and on the ASM.

The posive price spread between evening and central hours of the day is expected to persist in the short- term, as renewables penetraon remains under 40% of gross domesc consumpons.

Sustained solar development will sharpen the price decrease in the central hours of the day, especially in correspondence of large sunlight availability and low demand levels (e.g., during spring), gradually closing the gap between peak and off-peak prices.

The reverse trajectory of hourly price differenals is expected to connue in the long-term, favoring the increase of prices in off-peak hours. The growing penetraon of energy intensive electrochemical BESS and the generally greater operavity of storage units could dampen the cannibalizaon effect produced by non- programmable solar power plants.

High commodies prices connue to keep PUN elevated in the short-term and impact the equilibrium in the thermoelectric sector, parcularly gas-fired units. The significant rise in gas prices affects the variable costs of exisng CCGTs (the marginal technology in the Italian system), furthermore recovered of hydro generaon and presence of coal units in the mix determine a CSS below zero.

In the second half of the 2020s, it is expected that exisng CCGTs (Combined Cycle Gas Turbines) will benefit from the phase-out of coal-fired units in the peninsula and the growing demand, resulng in a baseload CSS (Clean Spark Spread) averaging around -2 €/MWh. However, this benefit will be challenged by factors such as the slowly decreasing trend of imported flows, intra-sectoral compeon from CM- supported newbuilds, and the growing trend of renewables.

In the long-term, renewables are expected to dominate the generaon mix. However, due to the decreasing trend of imported flows and increase in demand, exisng CCGTs are favored and are expected to remain the marginal technology in the system for at least 85% of the hours. This will result in the baseload CSS stabilizing near -1 €/MWh.

The effect of solar producon during central hours of the day is sll moderate as penetraon remains limited. Price differenals during the day aain current average levels.

As solar penetraon increases and the cannibalisaon effect intensifies, the spread between central and morning/evening peak hours increase. The development of single-axis tracker installaons, grid reinforcements, and power intensive storages only parally contain such effect.

As within-day price differenal and the number of hours in which prices reach 0 €/MWh increase, supporng investments in electrolysis capacity, me-shi􀅌ing applicaons on the DAM become interesng and trigger new investments in energy intensive storage units.

The CSS level is strictly connected to the evoluon of the market share of exisn CCGTs. During 2024 sll higher than historical level fuel prices guaranty a weak coal-to-gas switching condions, reducing gas market shares also affected by recover in hydro generaon. Furthermore, contracon in electricity demand exacerbate this trend.

The market compeon is expected to increase with the stable import flows from the northern borders, the rise in renewable capacity, and the entry of approximately 1.8 GW high-efficiency CCGTs, which were acquired through the 2024 Capacity Market aucons. These factors will keep the baseload CSS in negave territory. In the Low scenario, where renewable development is greater, and in the High scenario, where demand is lower, and the compeon within the thermoelectric sector is stronger, this effect will be even more pronounced.

A􀅌er 2030, a significant decrease in net import flows and the exit of some ageing capacity allow exisng CCGTs (53%-efficiency) to remain the marginal technology in the system for at least 85% of the hours, with the baseload CSS aaining around -1 €/MWh. Greater renewable penetraon in the Low scenario, maintain the baseload CSS below 4 €/Mwh also in the long-term. In the High scenario reduce renewable development favor CCGT producon increasing the baseload CSS.

Captured CSS evolve depending on the zone mix, with southern bidding zones suffering the high operavity of coal-fired units and significant risk of operaon at loss, while CCGT producing in the northern zone manage to guarantee posive margins at around 20 €/MWh , favoured by the current market dynamics.

As renewable capacity increases, exisng units tend to concentrate their operaons during evening hours to maximize captured margins. The high-efficiency gas-fired capacity captured CSS is subject to compeve market condions as new projects enter the market with support from the latest CM aucon. Despite this, the high efficiency of these projects enables them to maintain an average captured margin above 15 €/MWh.

Growing renewable penetraon intensifies overgeneraon phenomena and accentuates evening price spikes, determining an increasing trend for captured marginality for exisng units in the first half of the 2030s but load factors reduce progressively on increasing renewables share and increase compeon from high efficiency units.

Solar power plants benefit of record-high power prices, supported by extraordinary fuels prices.

Increasing pace of installaons and the consequent cannibalizaon and overgeneraon effects – only parally limited by power intensive storages and grid developments – have an impact on zonal captured prices, which trend diverges compared to baseload prices.

The increasing occurrence of overgeneraon serves as a market signal for the entry of energy-intensive storages, which parally migate the cannibalizaon phenomenon. A􀅌er 2030, the cannibalizaon effect becomes more noceable in the captured prices of solar energy, parcularly in southern market zones with higher renewable penetraon.

Captured prices are basically aligned to zonal baseload prices and benefit from high power prices.

Captured prices remain basically in line zonal baseload prices also in the long-term. The overgeneraon induced by the growing solar producon has a major impact in the early 2030s, but the results of both sources remain more connected to zonal market dynamics than to the evoluon of the price shape. Also, both sources benefit from a producon profile which is more distributed over the hours of the day and over the year.

Captured prices are basically aligned to zonal baseload prices and benefit from high power prices.

Captured prices remain basically in line zonal baseload prices also in the long-term. The overgeneraon induced by the growing solar producon has a major impact in the early 2030s, but the results of both sources remain more connected to zonal market dynamics than to the evoluon of the price shape. Also, both sources benefit from a producon profile which is more distributed over the hours of the day and over the year.